Wellbores are formed in subterranean formations for various purposes including, for example, the extraction of oil and gas from a subterranean formation and the extraction of geothermal heat from a subterranean formation. A wellbore may be formed in a subterranean formation using a drill bit, such as, for example, an earth-boring rotary drill bit. Different types of earth-boring rotary drill bits are known in the art, including, for example, fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), impregnated bits (impregnated with diamonds or other abrasive particles), and hybrid bits (which may include, for example, both fixed cutters and rolling cutters).
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. The drill string comprises a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface of the formation. When weight or other axial force is applied to the drill string and consequently to the drill bit, the rotating bit engages the formation and proceeds to form a wellbore. The weight or other force used to push the drill bit into and against the formation is often referred to as the “weight-on-bit” (WOB). As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. The rate at which the drill bit proceeds into the formation is often referred to as the “rate of penetration” (ROP). With each revolution of the drill bit, the drill bit proceeds into the formation a distance, often referred to as the “depth of cut” (DOC). The ROP and DOC may be related to the type of drill bit used, the WOB, the rate at which the drill bit rotates (i.e., the “revolutions per minute” (RPM)), the number of cutters or abrasive particles on the drill bit, the location or arrangement of the cutters or abrasive particles on the drill bit, the hardness of the formation material, etc.
During drilling of a formation, drill bits may wear down and become damaged, causing them to be less effective at drilling and maintaining a desirable (i.e., high) ROP. Lateral vibrations during drilling may cause a drill bit to rotate about, but offset from, the center of a borehole in an unstable fashion. This rotation about the center of the borehole is often referred to as “bit whirl” or “backwards whirl,” terms often used to describe a drill bit rotating about the center of a borehole in an opposite direction as the rotation of the drill bit and drill string as a whole. For example, FIG. 1A illustrates a borehole 10 with a drill bit 12 inside the borehole 10 experiencing backwards whirl. The drill bit 12 is rotating about its axis 13 in a counterclockwise direction 15. However, the drill bit 12 as a whole rotates about an axis 11 of the borehole 10 in a clockwise direction 14. Such backwards whirl can damage cutters and cause premature wear of drill bits. “Forward synchronous rotation” of a drill bit, which is a term used to describe rotation of the drill bit about a center of a borehole in the same direction as the rotation of the drill bit and drill string as a whole, typically causes less damage and wear to drill bits when compared to backwards whirl. For example, FIG. 1B illustrates a borehole 10 with a drill bit 12 inside the borehole 10 experiencing forward synchronous rotation. The drill bit 12 is rotating about its axis 13 in a clockwise direction 16 and the drill bit 12 as a whole is also rotating about an axis 11 of the borehole 10 in a clockwise direction. Drill bits may be designed to encourage such forward synchronous rotation to avoid or reduce damage and wear. In addition, it may be desirable to cause the angular velocity of forward synchronous rotation to be, on average, about the same velocity as the rotation of the drill bit and drill string as a whole, although instantaneous velocities may deviate from one another slightly.
One technique to control bit whirl and reduce bit wear and damage is to design the drill bit to experience a net imbalance force (when in operation), or, in other words, a force in a direction that encourages forward synchronous rotation. The magnitude of the imbalance force may be designed to be within a target range of a percentage of the WOB. So-called “high-imbalance” bits or “gun drill bits” have been introduced that have a region devoid of cutters to push the drill bit in a desired direction and at a desired force during operation. High-imbalance design of drill bits may be achieved through selectively tailoring the location and size of the cutter devoid region, or otherwise selectively altering the imbalance force. For example, cutter rake angle, location or arrangement of cutters or abrasive particles, exposure of cutters (i.e., the distance a cutter cuts into the formation), size or orientation of blades on the drill bit, etc., may be altered to selectively alter the imbalance force.